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| BBG > SEC Filings for BBG > Form 10-Q on 3-Nov-2009 | All Recent SEC Filings |
3-Nov-2009
Quarterly Report
The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, debt and equity market conditions, regulatory restrictions and changes, changes in estimates of proved reserves, potential failure to achieve production from exploration or development projects, capital expenditures and other uncertainties, as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2008 under the "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" sections and in Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The Company does not undertake any obligation to publicly update any forward-looking statements.
Overview
Bill Barrett Corporation ("we," "our" or "us") was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop natural gas and oil in the Rocky Mountain region of the United States. We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin of Wyoming. Also in 2002, we completed two additional acquisitions of properties in the Uinta (Utah), Wind River (Wyoming), Powder River (Wyoming) and Williston (North Dakota, South Dakota and Montana) Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in and around the Gibson Gulch field in the Piceance Basin of Colorado. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. We completed an acquisition in May 2006 of coalbed methane properties located in the Powder River Basin. In June 2007, we completed the sale of our Williston Basin properties. In June 2009, we completed an acquisition of unproved undeveloped acreage in the Cottonwood Gulch area of the Piceance Basin.
The financial information for the nine months ended September 30, 2009 and 2008 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.
Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
Nine Months Ended
September 30, Increase (Decrease)
2009 2008 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production $ 479,455 $ 463,759 $ 15,696 3 %
Commodity derivative gain (loss) (48,612 ) 3,647 (52,259 ) nm *
Other 1,547 3,730 (2,183 ) (59 )%
Operating Expenses
Lease operating expense 34,921 32,391 2,530 8 %
Gathering and transportation expense 40,012 29,746 10,266 35 %
Production tax expense 11,850 37,405 (25,555 ) (68 )%
Exploration expense 2,172 2,935 (763 ) (26 )%
Impairment, dry hole costs and abandonment expense 29,834 5,618 24,216 431 %
Depreciation, depletion and amortization expense 189,459 149,798 39,661 26 %
General and administrative expense (1) 29,193 30,124 (931 ) (3 )%
Non-cash stock-based compensation expense (1) 12,081 12,096 (15 ) nm *
Total operating expenses $ 349,522 $ 300,113 $ 49,409 16 %
Production Data:
Natural gas (MMcf) 63,859 54,173 9,686 18 %
Oil (MBbls) 517 473 44 9 %
Combined volumes (MMcfe) 66,961 57,011 9,950 17 %
Daily combined volumes (MMcfe/d) 245 208 37 18 %
Average Prices (2):
Natural gas (per Mcf) $ 7.02 $ 7.87 $ (0.85 ) (11 )%
Oil (per Bbl) 55.76 76.57 (20.81 ) (27 )%
Combined (per Mcfe) 7.12 8.12 (1.00 ) (12 )%
Average Costs (per Mcfe):
Lease operating expense $ 0.52 $ 0.57 $ (0.05 ) (9 )%
Gathering and transportation expense 0.60 0.52 0.08 15 %
Production tax expense 0.18 0.66 (0.48 ) (73 )%
Depreciation, depletion and amortization 2.83 2.63 0.20 8 %
General and administrative expense (3) 0.44 0.53 (0.09 ) (17 )%
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* Not meaningful.
(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $41.3 million and $42.2 million for the nine months ended September 30, 2009 and 2008, respectively, in the Unaudited Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.
(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues were increased by $225.9 million for the nine months ended September 30, 2009 and reduced by $12.9 million for the nine months ended September 30, 2008. As
Nine Months Ended
September 30,
2009 2008
Natural gas (per Mcf) $ 3.48 $ 8.11
Oil (per Bbl) $ 43.59 $ 99.47
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(3) Excludes non-cash stock-based compensation expense as described in footnote
(1) above. This presentation is a non-GAAP measure. Average costs per Mcfe
for general and administrative expense, including non-cash stock-based
compensation expense, as presented in the Unaudited Condensed Consolidated
Statements of Operations, were $0.62 and $0.74 for the nine months ended
September 30, 2009 and 2008, respectively.
Production Revenues. Production revenues increased to $479.5 million for the nine months ended September 30, 2009 from $463.8 million for the nine months ended September 30, 2008, primarily due to a 17% increase in production volumes offset by a 12% decrease in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The net increase in production volumes added approximately $71.2 million of production revenues, while the decrease in prices reduced production revenues by approximately $55.5 million. Production from our main areas of operation are summarized in the following table:
Nine Months Ended Nine Months Ended
September 30, 2009 September 30, 2008 % Increase (Decrease)
Oil Natural Gas Total Oil Natural Gas Total Oil Natural Gas Total
(MBbls) (MMcf) (MMcfe) (MBbls) (MMcf) (MMcfe) (MBbls) (MMcf) (MMcfe)
Piceance Basin 313 24,814 26,692 301 21,361 23,167 4 % 16 % 15 %
Uinta Basin 162 23,776 24,748 127 19,992 20,754 28 % 19 % 19 %
Wind River Basin 22 6,328 6,460 23 7,023 7,161 (4 )% (10 )% (10 )%
Powder River Basin - 8,682 8,682 - 5,777 5,777 - 50 % 50 %
Paradox Basin 1 195 201 - - - nm * nm * nm *
Other 19 64 178 22 20 152 (14 )% 220 % 17 %
Total 517 63,859 66,961 473 54,173 57,011 9 % 18 % 17 %
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* Not meaningful
Total production volumes for the nine months ended September 30, 2009 of 67.0 Bcfe increased from 57.0 Bcfe for the nine months ended September 30, 2008 due to increased production from the Piceance, Uinta and Powder River Basins, offset by a decrease in production in the Wind River Basin. The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 111 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Uinta Basin was the result of our continued development activities with initial sales from 48 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 228 new gross wells from October 1, 2008 to September 30, 2009. Although we have reduced our current year development activities in the Powder River Basin as the result of lower natural gas prices, our production in the Basin has benefited from prior year development programs due to the extended dewatering process of the coal bed methane wells. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines.
Hedging Activities. During the nine months ended September 30, 2009, approximately 75% of our natural gas volumes and 52% of our oil volumes were hedged, which resulted in an increase in gas revenues of $225.9 million and an increase in oil revenues of $6.3 million after settlements for all commodity derivatives, including basis only swaps. During the nine months ended September 30, 2008, approximately 72% of our natural gas volumes and 66% of our oil volumes were hedged, which resulted in a reduction in gas revenues of $12.9 million and a reduction in oil revenues of $10.8 million after settlements for all commodity derivatives.
Commodity Derivative Gain (Loss). Ineffectiveness on cash flow hedges related to
slight differences between the contracted location and the actual delivery
location is recognized in the line item titled "Commodity derivative gain
(loss)" in the Unaudited Condensed Consolidated Statements of Operations. We
also have basis only swaps for natural gas in the Rocky Mountain region, which
do not qualify for cash flow hedge accounting. The change in the fair value of
the derivative instruments that do not qualify for cash flow hedge accounting is
also recognized in this line item. In addition, effective September 1, 2009 we
elected to de-designate certain cash flow hedges in the Rocky Mountain region
and enter into physical fixed-price sales contracts for a portion of our
anticipated October 2009 natural gas production. As a result, subsequent changes
to the fair value of these derivatives will also be reflected in "Commodity
derivative gain (loss)." We will continue to consider short term circumstances
in the gas markets and make assessments as to whether we will enter into
additional physical fixed-price sales contracts in the future.
The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain (loss) for the periods indicated:
Nine Months Ended
September 30,
2009 2008
Realized losses on derivatives not designated as cash flow
hedges $ (2,446 ) $ (963 )
Unrealized ineffectiveness gains (losses) recognized on
derivatives designated as cash flow hedges (5,721 ) 3,121
Unrealized gains (losses) on derivatives not designated as
cash flow hedges (40,445 ) 1,489
Total commodity derivative gain (loss) $ (48,612 ) $ 3,647
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Other Operating Revenues. Other operating revenues decreased to $1.5 million for the nine months ended September 30, 2009 from $3.7 million for the nine months ended September 30, 2008. Other operating revenues for the nine months ended September 30, 2009 consisted of gathering, compression and salt water disposal fees received from third parties. Other operating revenues for the nine months ended September 30, 2008 primarily consisted of gains realized from the sale of properties of $1.1 million, gathering and rental fees of $1.6 million and the sale of seismic data of $1.0 million.
Lease Operating Expense. Lease operating expense decreased to $0.52 per Mcfe for the nine months ended September 30, 2009 from $0.57 per Mcfe for the nine months ended September 30, 2008. The following table displays the lease operating expense by basin:
Nine Months Ended Nine Months Ended
September 30, 2009 September 30, 2008 %Increase/(Decrease)
($ in thousands) ($ per Mcfe) ($ in thousands) ($ per Mcfe) ($ per Mcfe)
Piceance Basin $ 10,933 $ 0.41 $ 7,482 $ 0.32 28 %
Uinta Basin 8,401 0.34 11,852 0.57 (40 )%
Wind River Basin 3,897 0.60 4,821 0.67 (10 )%
Powder River Basin 10,949 1.26 7,799 1.35 (7 )%
Paradox Basin 270 1.34 - - nm *
Other 471 2.65 437 2.83 7 %
Total $ 34,921 $ 0.52 $ 32,391 $ 0.57 (9 )%
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* Not meaningful
Lease operating expense increased in the Piceance Basin to $0.41 per Mcfe for the nine months ended September 30, 2009 from $0.32 per Mcfe for the nine months ended September 30, 2008 primarily due to increased compression costs associated with the Bailey Compressor Station that was placed into service in July 2008. The decrease in lease operating expense in the Uinta Basin to $0.34 per Mcfe for the nine months ended September 30, 2009 from $0.57 per Mcfe for the nine months ended September 30, 2008 was the result of decreased water disposal costs due to the utilization of a salt water disposal well, as well as a decrease in compressor overhaul activity in our West Tavaputs field. In addition, for the first half of 2009 we shut in a majority of our Lake Canyon and Blacktail Ridge fields due to gas gathering constraints, which reduced our lease operating expense in the Uinta Basin. Lease operating expense decreased in the Wind River Basin to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.67 per Mcfe for the nine months ended September 30, 2008 as a result of decreased workover activity and reduced water handling costs. Lease operating expense decreased in the Powder River Basin to $1.26 per Mcfe for the nine months ended September 30, 2009 from $1.35 per Mcfe for the nine months ended September 30, 2008 primarily as a result of decreased power, fuel and labor costs. Initial production from wells in the Powder River Basin that were previously in the dewatering stage increased production without increasing costs, which also reduced the cost per Mcfe in that basin.
Gathering and Transportation Expense. Gathering and transportation expense increased to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.52 per Mcfe for the nine months ended September 30, 2008. The following table displays the gathering and transportation expense by basin:
Nine Months Ended Nine Months Ended
September 30, 2009 September 30, 2008 %Increase/(Decrease)
($ in thousands) ($ per Mcfe) ($ in thousands) ($ per Mcfe) ($ per Mcfe)
Piceance Basin $ 15,288 $ 0.57 $ 12,046 $ 0.52 10 %
Uinta Basin 14,964 0.60 10,670 0.51 18 %
Wind River Basin 39 0.01 125 0.02 (50 )%
Powder River Basin 9,518 1.10 6,890 1.19 (8 )%
Paradox Basin 174 0.87 - - nm *
Other 29 0.16 15 0.10 60 %
Total $ 40,012 $ 0.60 $ 29,746 $ 0.52 15 %
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* Not meaningful
Gathering and transportation expense increased in the Piceance Basin to $0.57 per Mcfe for the nine months ended September 30, 2009 from $0.52 per Mcfe for the nine months ended September 30, 2008. The increase is primarily attributable to our election to process our gas in order to sell the resulting natural gas liquids ("NGLs"). Beginning in January 2009, we incurred additional fees to process our natural gas and received additional revenue from the sale of NGLs. Although sales revenue for NGLs can fluctuate based on monthly index prices, for the nine months ended September 30, 2009, we realized a Company-wide increase of approximately $0.24 per Mcfe to our average realized price while incurring additional gathering and processing costs of approximately $0.07 per Mcfe. Gathering and transportation expense in the Uinta Basin increased to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.51 per Mcfe for the nine months ended September 30, 2008. This increase is a result of additional contracts to gather, process and transport our West Tavaputs gas from the Uinta Basin. Also contributing to the increases in both basins were higher fees associated with the Rockies Express Pipeline ("REX") due to the completion of an additional segment of the pipeline that gave us access to midcontinent delivery points farther east.
We have long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to reduce the risk and impact related to production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance, Uinta and Powder River Basins where we expect to allocate a significant portion of our capital expenditure program in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in the above gathering and transportation expense is $0.17 and $0.12 per Mcfe of firm transportation expense for the nine months ended September 30, 2009 and 2008, respectively, along with $0.05 per Mcfe of processing expense from long-term contracts for both the nine months ended September 30, 2009 and 2008.
The increase in firm transportation expense to $0.17 per Mcfe for the nine months ended September 30, 2009 from $0.12 per Mcfe for the nine months ended September 30, 2008 was the result of the additional contracts executed for our West Tavaputs gas and increased fees for REX transportation as mentioned above.
Production Tax Expense. Total production taxes decreased to $11.9 million for the nine months ended September 30, 2009 from $37.4 million for the nine months ended September 30, 2008. The decrease in production taxes is primarily related to decreased natural gas and oil prices during the nine months ended September 30, 2009. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. In addition to the decrease in natural gas and oil prices, on March 23, 2009 we entered into a settlement agreement with the State of Colorado that allowed additional deductions against the gross taxable value of our production related to our 2004 through 2006 severance tax returns. As a result, severance tax expense was reduced by $0.8 million related to the 2004 through 2006 tax years. Based on this settlement, we revised our estimates of 2007 and 2008 Colorado severance tax, which reduced our production tax expense by an additional $4.0 million. Excluding the reduction associated with the Colorado severance tax, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.8% for the nine months ended September 30, 2009 and 7.7% for the nine months September 30, 2008. Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.
Exploration Expense. Exploration expense decreased to $2.2 million for the nine months ended September 30, 2009 from $2.9 million for the nine months ended September 30, 2008. Exploration expense for the nine months ended September 30, 2009 consisted of $0.8 million for seismic programs, principally in the Paradox Basin, $0.4 million related to the evaluation of non-acquired assets and $1.0 million for delay rentals and other costs across all basins. Exploration expense for the nine months ended September 30, 2008 consisted of $2.2 million for seismic programs, principally in the Deseret, Uinta, Paradox and Big Horn Basins, along with $0.7 million for delay rentals and other exploration costs.
Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $29.8 million during the nine months ended September 30, 2009 from $5.6 million during the nine months ended September 30, 2008. For the nine months ended September 30, 2009, abandonment expense associated with exploratory drilling locations was $1.2 million, expired leasehold costs were $1.5 million and dry hole costs were $27.1 million. The $27.1 million in dry hole costs were associated with six exploratory wells in the Montana Overthrust area, three exploratory wells in the Hook prospect of the Uinta Basin and one exploratory well in each of the Big Horn Basin, the Yellow Jacket prospect of the Paradox Basin, the Salt Flank prospect of the Paradox Basin and the Woodside prospect of the Uinta Basin, each of which were tested and determined to be non-commercial. For the nine months ended September 30, 2008, abandonment expense associated with exploratory drilling locations was $0.2
million, expired leasehold costs were $0.6 million and dry hole costs included $3.4 million for a well drilled in the Uinta Basin and $1.4 million related to additional costs on wells that were deemed to be uneconomic in prior years. The $3.4 million for dry hole costs were associated with the Peters Point 7-1-13-16 Ultra Deep well, which was completed in June 2008, and was tested and determined to be non-commercial in the Pennsylvanian Weber and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed. For the nine months ended September 30, 2009 and 2008, we did not incur any impairment charges related to the net carrying value of our development areas.
Depreciation, Depletion and Amortization ("DD&A"). DD&A was $189.5 million for the nine months ended September 30, 2009 compared to $149.8 million for the nine months ended September 30, 2008. The increase of $39.7 million was a result of a 17% increase in production for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, along with an increase in the DD&A rate. The increase in production accounted for $26.2 million of additional DD&A . . .
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